Upconverting nanoparticles as tracers for production and well monitoring

ABSTRACT

A method of fracturing multiple productive zones of a subterranean formation penetrated by a wellbore is disclosed. The method comprises injecting a fracturing fluid into each of the multiple production zones at a pressure sufficient to enlarge or create fractures in the multiple productive zones, wherein the fracturing fluid comprises an upconverting nanoparticle that has a host material, a dopant, and a surface modification such that the upconverting nanoparticle is soluble or dispersible in water, a hydrocarbon oil, or a combination thereof; recovering a fluid from one or more of the multiple production zones; detecting the upconverting nanoparticle in the recovered fluid by exposing the recovered fluid to an excitation radiation having a monochromatic wavelength; and identifying the zone that produces the recovered fluid or monitoring an amount of water or oil in the produced fluid by measuring an optical property of the upconverting nanoparticle in the recovered fluid.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.16/009,758 filed on Jun. 15, 2018, which is incorporated by reference inits entirety herein.

BACKGROUND

Tracers have been used in the oil and gas industry to provide valuablereservoir information such as productivity of producing formations orzones, inter-well connections, heterogenetities, and water movements.Traditionally, fluorescent tracers are used for these activities. Onelimitation of these fluorescent tracers, however, is the overlap of thesignals from the tracers and the signals from certain organic moleculesthat are present in the wellbore fluids, making it difficult to makeaccurate measurements. Thus, the industry is receptive to alternativetracers and improved methods for reservoir monitoring and evaluation.

BRIEF DESCRIPTION

A method of fracturing multiple productive zones of a subterraneanformation penetrated by a wellbore is disclosed. The method comprisesinjecting a fracturing fluid into each of the multiple production zonesat a pressure sufficient to enlarge or create fractures in the multipleproductive zones, wherein the fracturing fluid comprises an upconvertingnanoparticle that has a host material, a dopant, and a surfacemodification such that the upconverting nanoparticle is soluble ordispersible in water, a hydrocarbon oil, or a combination thereof;recovering a fluid from one or more of the multiple production zones;detecting the upconverting nanoparticle in the recovered fluid byexposing the recovered fluid to an excitation radiation having amonochromatic wavelength; and identifying the zone that produces therecovered fluid or monitoring an amount of water or oil in the producedfluid by measuring an optical property of the upconverting nanoparticlein the recovered fluid.

In another embodiment, a method of determining water breakthrough in aproduction well associated with one or more injection wells comprisesintroducing a fluid comprising an upconverting nanoparticle into aninjection well, the upconverting nanoparticle having a host material, adopant, and a surface modification such that the upconvertingnanoparticle is soluble or dispersible in both water and a hydrocarbonoil; flowing at least a portion of the fluid comprising the upconvertingnanoparticle from the injection well into the production well; producinga production fluid from the production well; detecting the upconvertingnanoparticle in the production fluid by exposing the production fluid toan excitation radiation having a monochromatic wavelength; anddetermining water breakthrough in the production well by qualitativelydetermining the presence or quantitatively measuring the amount of theupconverting nanoparticle in the production fluid.

In yet another embodiment, a method of monitoring well productioncomprises introducing an upconverting nanoparticle into a wellbore, theupconverting nanoparticle having a host material, a dopant, and asurface modification such that the upconverting nanoparticle is solubleor dispersible in water, a hydrocarbon oil, or a combination thereof;producing a fluid from the wellbore, the produced fluid containing theupconverting nanoparticle; exposing the upconverting nanoparticle to anexcitation radiation from an electromagnetic radiation source within thewellbore; and identifying a zone that produces the fluid or monitoringan amount of water or oil in the produced fluid by measuring an opticalproperty of the upconverting nanoparticle in the produced fluid withinthe wellbore.

In still another embodiment, a method of monitoring well productioncomprises introducing a cable comprising an upconverting nanoparticleinto a wellbore, the upconverting nanoparticle having a host material, adopant, and a surface modification such that the upconvertingnanoparticle is soluble or dispersible in water, a hydrocarbon oil, or acombination thereof; exposing the upconverting nanoparticle to anexcitation radiation while the upconverting nanoparticle is exposed to afluid produced from the wellbore; and measuring an optical property ofthe upconverting nanoparticle to determine a zone that produces thefluid or monitoring an amount of water or oil in the produced fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way.With reference to the accompanying drawings, like elements are numberedalike:

FIG. 1 is a scheme illustrating that up converting nanoparticles canhave different emission wavelengths with a single excitation of 980 nmby choosing suitable dopants;

FIG. 2 is a schematic representation of surface modification ofnanoparticles with citrate to make tracers water dispersible;

FIG. 3A shows the SEM image of surface functionalized upconvertingnanoparticles NaYF4: Yb, Er (A, T1) and FIG. 3B shows the SEM image ofsurface functionalized upconverting nanoparticles NaYF4:Yb, Tm (B, T2);

FIG. 4 illustrates a flow testing diagram;

FIG. 5 shows nanoparticle size frequency curve for tracer T1;

FIG. 6 shows nanoparticle size frequency curve for tracer T2;

FIG. 7 shows the luminescence spectrum of tracer T1, T2, or acombination thereof in an API brine/crude oil/water emulsion at 980 nmexcitation;

FIG. 8 shows eluting concentration in part per billion (ppb) for tracerT1 and tracer T2;

FIG. 9 shows the emission spectra of water emulsions containing anupconverting nanoparticle at 980 nm excitation;

FIG. 10 shows the intensity of emission as a function of water contentfor a fluid containing an upconverting nanoparticle at 980 nmexcitation; and

FIG. 11 is a schematic illustration of a system that is disposed in adownhole environment according to an embodiment of the disclosure.

DETAILED DESCRIPTION

The inventors have found that upconverting nanoparticles as disclosedherein can be used as alternative luminescent tracers. Theseupconverting nanoparticles have low energy excitation around 980 nm withhigh-energy emissions in the region of 200 to 950 nm. In particular, thesignals from these upconverting nanoparticles are readilydistinguishable from the signals generated from those organic moleculesthat are commonly injected into a wellbore during various operations,thus minimizing the background noise and providing reliable informationfor production and well monitoring. In addition, the upconvertingnanoparticles are environmentally friendly. They are compatible withbrines and oils and are stable at elevated temperatures for an extendedperiod of time, thus these upconverting nanoparticles can be used invarious downhole applications.

The upconverting nanoparticles have a host material, a dopant, and asurface modification such that the upconverting nanoparticle is solubleor dispersible in water, a hydrocarbon oil, or a combination thereof.

The host material of the upconverting nanoparticle is an inorganiccompound having an ion of Y³⁺, La³⁺, Gd³⁺, Sc⁺, Ca²⁺, Sr²⁺, Ba²⁺, Zr⁴⁺or Ti⁴⁺. Preferably, the host material comprises NaYF₄, NaGdF₄, LiYF₄,YF₃, CaF₂, Gd₂O₃, LaF₃, Y₂O₃, ZrO₂, Y₂O₂S, La₂O₂S, Y₂BaZnO₅, orGd₂BaZnO₅.

The dopant ions play a central role by absorbing and emitting thephotons. They determine, for example, the color of the emitted light.The upconverting nanoparticles can have multicolors, which is achievedby utilizing the different dopants. FIG. 1 shows the scientificphenomenon taking place in upconverting nanoparticles and illustratesthat the emission wavelength can be tuned by choosing different dopants.

The dopant ion occupies part of the cation sites in the host lattice,and preferably the dopants and host lattice cations have a similar size.Examples of the dopants include Er', Yb³⁺, Tm³⁺, Ho³⁺, Pr³⁺, Nd³⁺, Dy³⁺,Ti²⁺, Ni²⁺, Mo³⁺, Re⁴⁺, Os⁴⁺, or a combination comprising at least oneof the foregoing. Preferably, the dopant of the upconvertingnanoparticle comprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺ or a combinationcomprising at least one of the foregoing.

In an embodiment, dopant ions used in the upconverting nanoparticles arethe pairs erbium-ytterbium (Er³⁺, Yb³⁺) or thulium-ytterbium (Tm³⁺,Yb³⁺). In such combinations ytterbium ions are added as antennas, toabsorb light at around 980 nm and transfer it to the upconverter ion. Ifthe upconverter ion is erbium, then a characteristic green and redemission is observed, while when the upconverter ion is thulium, theemission includes near-ultraviolet, blue and red light. The dopant cancomprise about 5 mol % to about 30 mol % of

Yb³⁺ and about 1 mol % to about 3 mol % of one or more of the following:Tm³⁺, Ho³⁺, or Er³⁺, each based on the total mole of the upconvertingnanoparticle.

The upconverting nanoparticles can be functionalized to include chemicalfunctional groups to increase dispersibility, solubility, compatibility,stability and other desirable properties of the upconvertingnanoparticles in water, brine, oil, as well as emulsions thereof. Asused herein, “functionalized upconverting nanoparticles” include bothnon-covalently functionalized upconverting nanoparticles and covalentlyfunctionalized upconverting nanoparticles. Non-covalentfunctionalization is based on van der Walls forces, hydrogen bonding,ionic interactions, dipole-dipole interactions, hydrophobic or π-πinteractions. Covalent functionalization means that the functionalgroups are covalently bonded to the upconverting nanoparticles, eitherdirectly or via an organic moiety.

One way to functionalize upconverting nanoparticles is to grow anamorphous silica shell around the particles. The chemistry of silica iswell known, and the properties of silica are very advantageous. A silicalayer increases the negative charge of the surface and thereforeenhances the dispersibility of the upconverting nanoparticles in polarsolvents. As an example, hydrolysis reaction of monomeric tetraethylorthosilicate (TEOS) followed by a condensation step generates ahydrophilic polymer that coats upconverting nanoparticles. The type offunctionalization (e.g., amino, thiol or carboxyl group) can be tuned bychoosing an appropriate organosilane (e.g., 3-aminopropyltriethoxysilane(APTS), 3-mercaptopropyltriethoxysilane or 11-dimethylchlorosilylundecanoyl chloride) to copolymerize with TEOS.

Upconverting nanoparticles may be coated with multilayers by consecutiveadsorption of polyanions such as poly(styrene sulfonate) and polycationssuch as poly(allylamine hydrochloride). The thickness of the coating iscontrolled by adjusting the number of deposited layers.

Upconverting nanoparticles can also be coated with polyarcylic acid(PAA), polyethylene glycol (PEG), or a copolymer thereof. Depending onthe methods of making, the upconverting nanoparticles can have differentoriginal ligands. The original ligand on the upconverting nanoparticlescan bind the polymer by attracting their hydrophobic alkyl chains, andconsequently the ligand is masked while hydrophilic segments of thecopolymer bearing the selected functional groups cover the outersurface. The original ligand may be exchanged to another one such ascitric acid, PEG diacid, dendrimer, hexanedioic acid or PEG-phosphonate,and the like.

The upconverting nanoparticles can have an average particle size of lessthan about 100 nm, for example about 20 to about 90 nm. The thickness ofthe coating, if present, can be in the range of about 1 nm to about 15nm or about 1 nm to about 10 nm.

The upconverting nanoparticles can be introduced into a subterraneanformation penetrated by a wellbore, and by analyzing a sample of thefluid obtained from the wellbore, various properties of the subterraneanformation can be obtained. As used herein, analyzing the sample includedetermining the presence or absence of the upconverting nanoparticles aswell as measuring one or more optical properties of the upconvertingnanoparticles. The optical properties of upconverting nanoparticlesnormally can be used to determine at least one property of thesubterranean formation penetrated by a well. Exemplary opticalproperties include an absorption spectrum, an absorption intensity, apeak absorption wavelength, an emission spectrum, a peak emissionwavelength, and a fluorescence intensity of upconverting nanoparticles.Methods of measuring the optical properties of upconvertingnanoparticles are known in the art and are not particularly limited.

Exemplary properties or information that can be determined include aproduction zone within the subterranean formation, the productivity ofthe zones within the formation, an identification of injection wellcontributing to the flow of breakthrough water, flow paths through thesubterranean formation, and the like. By analyzing the information andtaking appropriate actions, the production of hydrocarbons can beimproved.

In an embodiment, the upconverting nanoparticles are introduced into thesubterranean formation with a fluid delivery system configured todeliver a fluid having the upconverting nanoparticles suspended thereinto the subterranean formation.

Delivery fluids transporting upconverting nanoparticles into theformation are aqueous or non-aqueous based. Exemplary carriers includebrine, such as a potassium chloride or sodium chloride brine or divalentbrine such as calcium chloride or zinc bromide brine; salt water such asseawater; fresh water; a liquid hydrocarbon; or a surfactant basedfluid. The upconverting nanoparticles may further be injected into theformation in gas such as carbon dioxide, nitrogen and carbondioxide/nitrogen, liquefied gas, such as liquefied natural gas orliquefied petroleum gas as well as in foams. The delivery fluid ispreferably aqueous, steam or gas (water flooding, steam flooding or gasflooding).

Generally, fluids pumped into the formation, injection well, orproduction well do not require excessive amounts of the upconvertingnanoparticles. The minimum amount of upconverting nanoparticles in thefluid introduced into the formation, the production well or injectionwell is that amount sufficient to permit detection within a producedfluid. Typically, the amount of upconverting nanoparticles present inthe introduced fluid is between from about 0.1 ppb to about 500,000 ppm.

The upconverting nanoparticles may be detected in recovered producedfluids. Thus, in some embodiments, the methods described herein do notrequire downhole equipment for detection. Fluids transported out of thewell are evaluated, and the upconverting nanoparticles can be identifiedat a location distant from the wellbore.

The upconverting nanoparticles may be used to identify a source offluids produced from a production well. As an example, upconvertingnanoparticles may be introduced proximate the aquifer zone. Producedfluids may be analyzed to determine if the produced fluids include anoptical property of the upconverting nanoparticles introduced into theaquifer zone. Identification of the corresponding optical property maybe an indication that the produced fluid includes water from the aquiferzone.

Upconverting nanoparticles exhibiting different optical properties maybe introduced into various zones of the subterranean formation todetermine a location (e.g., a zone) from which produced fluids (e.g.,hydrocarbons, water, etc.) originate. In other words, the upconvertingnanoparticles introduced into different zones are qualitatively (andoptionally also quantitatively) distinguishable in order to identify thezone or area within the formation from which a produced fluidoriginates. As such, the upconverting nanoparticles introduced into eachof the zones being treated preferably exhibit unique absorption andoptical properties such that the properties of upconvertingnanoparticles introduced into one zone is unable to mask the propertiesof upconverting nanoparticles introduced into another zone. Thus, aproduced fluid exhibiting an optical property corresponding to aproperty of upconverting nanoparticles introduced into a zone of thesubterranean zone may be an indication that the produced fluidoriginated from the zone in which the upconverting nanoparticles wereintroduced.

Advantageously, the nanoparticles introduced into different zones emit adifferent color of light when exposed to the same excitation radiationhaving a monochromatic wavelength. In an embodiment, the monochromaticwavelength is about 980 nanometers (nm). Thus different types of theupconverting nanoparticles can be conveniently detected with the sameexcitation radiation.

In some embodiments, the upconverting nanoparticles may be introducedinto the subterranean formation during stimulation processes.Stimulation processes such as, for example, hydraulic fracturing (i.e.,“fracing”) may be used to enhance hydrocarbon recovery from ahydrocarbon-bearing subterranean formation. In hydraulic fracturingoperations, hydraulic fractures may be created or enlarged by injectinga fluid containing additives and including a suspended proppant material(e.g., sand, ceramics, etc.) into a targeted subterranean formationunder elevated pressure conditions sufficient to cause thehydrocarbon-bearing formation material to fracture. The upconvertingnanoparticles may be included in the fracturing fluid. Thus, in anembodiment, a method of fracturing multiple zones of a subterraneanformation penetrated by a well comprises: pumping into each zone of theformation to be fractured a fracturing fluid, wherein the fracturingfluid pumped into each zone comprises a qualitatively distinguishabletracer comprising upconverting nanoparticles which are eitherhydrocarbon soluble/dispersible, water soluble/dispersible or bothhydrocarbon soluble/dispersible and water soluble/dispersible; enlargingor creating a fracture in the formation; recovering fluid from at leastone of the multiple zones; and identifying the zone within thesubterranean formation from which the recovered fluid was produced byidentifying the upconverting nanoparticles in the recovered fluid. Inanother embodiment, a method of monitoring the production of fluidsproduced in multiple productive zones of a subterranean formationpenetrated by a well comprises pumping fracturing fluid into themultiple productive zones at a pressure sufficient to enlarge or createfractures in each of the multiple productive zones, wherein thefracturing fluid comprises upconverting nanoparticles which are eitherhydrocarbon soluble/dispersible, water soluble/dispersible or bothhydrocarbon soluble/dispersible and water soluble/dispersible andfurther wherein the fluorescent upconverting nanoparticles pumped intoeach of the multiple productive zones is qualitatively and/orquantitatively distinguishable; and monitoring the amount of fluids(water or oil) produced from at least one of the multiple productivezones from the upconverting nanoparticles in the produced fluid.

In an embodiment, the upconverting nanoparticles are present incomposites where they are immobilized in a matrix or coated on a solidsupport. Exemplary matrix includes an emulsion, a binder (e.g.compressing upconvering nanoparticles with a binder into a solidparticulate), a porous particulate, an inorganic material having alayered structure, or the like. Preferably the upconvertingnanoparticles can be released in a controlled manner from thecomposites. The controlled release of the upconverting nanoparticles maybe dependent upon the surface charges between the tracer and supportwhich, in turn, may be dependent on the adsorption/desorption propertiesof the tracer to adsorbent, pH variations, salinity, hydrocarboncomposition, temperature, and pressure.

In addition to monitoring different zones in hydrocarbon productionwells and determining the zone in which hydrocarbons have been producedfrom the formation, the upconverting nanoparticles may also be used tomonitor the amount of oil and/or water produced. In particular, theinventors have found that upconverting nanoparticles such as oil solubleor oil dispersible ones, can be used to quantify the amount of oil(hydrocarbon) in a fluid produced from a wellbore, and water soluble orwater dispersible upconverting nanoparticles can be used to quantify theamount of water in a fluid produced from a wellbore. Such fluids can bea water in oil or oil in water emulsion.

Further, the upconverting nanoparticles may also be used to determinesites of flowback water and produced water as well as for detection orearly warning of phenomena such as water breakthrough. The upconvertingnanoparticles may be introduced into an injection fluid during at leastone of water flooding, steam assisted gravity drainage, steam flooding,cyclic steam stimulation, or other enhanced oil recovery stimulationprocesses to determine fluid flow paths through the subterraneanformation and into produced fluids.

In other embodiments, qualitatively distinguishable upconvertingnanoparticles are preferably introduced into the aqueous fluidintroduced into the different injection wells. The upconvertingnanoparticles used in this embodiment are typically water dispersible.Fluids produced from one or more production wells may be analyzed forthe presence of the upconverting nanoparticles in the produced fluid.The presence of upconverting nanoparticles in produced fluids from aproduction well may indicate water breakthrough. The injection well,into which the water in the breakthrough water has been determined tohave been initially introduced, can be shut off. Thus, the upconvertingnanoparticles can be used to optimize enhancement of hydrocarbons duringsecondary recovery operations by shutting down the injection well andterminating the flow of water from the injection well directly into theproduction well.

The upconverting nanoparticles may also be used to sweep a productionwell in an enhanced oil recovery (EOR) operation, such as flooding.Upconverting nanoparticles may be introduced into injection fluid andthe injection fluid is then introduced into the formation. The injectionfluid may be introduced by being pumped into one or more injectionwells. Typically, the upconverting nanoparticles are dispersible in thedelivery fluid. The detection of the upconverting nanoparticles influids produced from the production well is indicative that the sweep,i.e., removal of the oil from pore spaces within the formation, has beencompleted.

If needed, the upconverting nanoparticles can be analyzed within thewellbore. In an embodiment, a method of monitoring well productioncomprises introducing an upconverting nanoparticle as disclosed hereininto a wellbore; producing a fluid from the wellbore, the produced fluidcontaining the upconverting nanoparticle; exposing the upconvertingnanoparticle to an excitation radiation from an electromagneticradiation source within the wellbore; and identifying a zone thatproduces the fluid or monitoring an amount of water or oil in theproduced fluid by measuring an optical property of the upconvertingnanoparticle in the produced fluid within the wellbore.

Alternatively or in addition, a method of monitoring well productionincludes introducing a cable comprising an upconverting nanoparticle asdisclosed herein into a wellbore; exposing the upconverting nanoparticleto an excitation radiation while the upconverting nanoparticle isexposed to a fluid produced from the wellbore; and measuring an opticalproperty of the upconverting nanoparticle to determine a zone thatproduces the fluid or monitoring an amount of water or oil in theproduced fluid. The cable can be a fiber optic cable. The nanoparticlescan be present as a coating on a portion of the fiber optic cable. Thenanoparticles can also be dispersed in at least a portion of the fiberoptic cable.

A radiation source can be located within the wellbore to provide theexcitation radiation to the upconverting nanoparticles. For example, aradiation source (e.g., a light source) may be coupled to a fiber opticcable, which may transmit the excitation radiation to the upconvertingnanoparticles. Responsive to exposure to the excitation radiation, theupconverting nanoparticles re-emit radiation at a different wavelengththan the excitation wavelength, and the emitted radiation can betransmitted through an optical fiber to a detector to measure thedesired optical properties of the upconverting nanoparticles.

Referring to FIG. 11, a wellbore system 100 includes a fiber optic cable103 extending from a surface location of a subterranean formation tolocations adjacent to one or more zones within the subterraneanformation. The zones are separated by packers 104 and may have fractures105. The fiber optic cable 103 can extend along an interior of aproduction string 102. One or more analysis unit (106) can be coupled tothe fiber optic cable. The analysis unit can include a radiation sourceand a detector. The detected signals from the upconverting nanoparticlescan be processed either downhole or on the surface. The results can bedisplaced and stored at an electronic device such as a computer 107.

EXAMPLES

Upconverting tracers used in the examples have a host material (matrix)of NaYF₄ with dopants of Yb and Er for green emission (T1) or Yb and Tmfor red emission (T2). These nanoparticles are synthesized in oleicacid/oleyalamine mixture at temperature around 300° C. The synthesizedupconverting nanoparticles have functional groups that are oleic acid,which makes them to be soluble in oil due to their hydrophobic behavior.

To make these particles to be dispersible in water, the oleic acidfunctional groups can be exchanged or modified with different chemicalfunctional groups. An exchange reaction with citric acid is illustratedin FIG. 2.

Stable crude oil emulsion was prepared by mixing 2 mL of a surfactantwith 100 mL of an API brine and 500 microliters of oil. The mixture wassonicated (2 h) in a sonication bath to obtain an oil in water emulsion.The API brine was prepared by dissolving 200 g of sodium chloride and 50g of calcium chloride dihydrate in de-ionized water (2.25 L).

Upconverting nanoparticle tracers were analyzed by scanning electronmicroscopy (SEM) using a field-emission scanning electron microscope.Luminescence measurements were obtained by using a Horiba Jobin YvonFluorolog 3 spectrofluorometer equipped with a single gratingmonochromator and a photomultiplier tube detector having an accuracy of0.5 nm modified with light source of 980 nm CW laser of 2 W energy. TheSEM images of tracers 1 and 2 are shown in FIG. 3A and FIG. 3Brespectively.

The surface modified nanoparticles were tested for its hydrodynamicradius. The particle size distributions measured at 70° C. for dilutedispersion of Tracer 1 and Tracer 2 separately in de-ionized are shownin FIG. 5 and FIG. 6. Mean particle size and poly-dispersity index fromthe same measurements are shown in Table 1. Size measurements wereconducted for two hours. The size for Tracer 1 and Tracer 2 is found tosmall enough to pass thorough the flow cell in the sand pack experimentand we anticipate no particle size related losses in the sand pack.

TABLE 1 Nanoparticle Size (nm) PDI Tracer 1 48 ± 18 0.14 Tracer 2 35 ±15 0.34

Luminescence measurements were performed on the tracer particles presentin crude oil/API brine/water emulsion. Tracer 1 (25 ppm), tracer 2 (25ppm), and a combination of tracer 1 and tracer 2 (25 ppm) areindependently dispersed in the crude oil/API brine emulsion. FIG. 7shows the luminescence spectrum of trace T1, tracer T2, or a combinationthereof in API brine/crude oil/water emulsion. The results show that T1has a green emission with a maximum wavelength around 542 nm and T2 hasa red emission with a maximum wavelength around 800 nm. These peakfeatures are maintained in the mixture of two tracers. For the furtheranalysis of the samples in the static and flow experiment peaks at 542and 800 nm are used for T1 and T2 respectively.

Static adsorption test was performed on the powder of calcium carbonatepowder (MILCARB 150) and 20/40 mesh sands. 0.25 grams of MILCARB 150(sample 1 & 3) and 0.25 grams 20/40 mesh sand (sample 2 & 4) were takenseparately in glass tubes. One ppm concentration of the mixture oftracer 1 and tracer 2 was prepared separately in the API brine and theoil-in-water emulsion. Five millimeters of the solution was injected inthe each tube. All the tubes were shaken gently and put in an oven at70° C. for 15 hours. After 15 hours, tubes were removed from the ovenand allowed to cool to room temperature. Liquid portion of the tubeswere analyzed on fluorolog for the concentration measurements.

Liquid portion of the tubes were analyzed on fluorolog for theconcentration measurements. From the difference in the initial and finalconcentration of tracers in the aqueous phase, adsorption on the powderwas calculated, and the results are shown in Table 2.

TABLE 2 Tube Particle % Adsorption % Adsorption No. Type Fluid for T1for T2 1 MILCARB 150 API Brine 62 71 2 20/40 Sands API Brine 25 40 3MILCARB 150 Oil-in-Water 59 64 Emulsion 4 20/40 Sands Oil-in-Water 4 31Emulsion

The tracers in API brine have more adsorption as compared to tracers inthe oil-in-Water emulsion. Without wishing to be bound by theory, it isbelieved that the electrostatic interaction of ions in the API brinewith the polar components in the crude oil results in their lesserinteractions with the tracers, leading to lower adsorption. Similarly,the adsorption on the 20/40 sand is lower, indicating tracer 1 andtracer 2 has less affinity towards negatively charged surfaces like20/40 sands.

The system 4 as shown in Table 2 was selected for flow experiment. Flowtesting of the T1 and T2 mixture in the crude oil/API brine emulsion wasconducted on a sand pack flow setup. The experiment was conducted at theflow rate of 5 mL/min at 70° C. Gravel pack sand (20/40 mesh) was filledand compressed in the flow cell to prepare 4.4 inches tall sand packcolumn. Initially, API brine at 5 mL/min flow rate was injected throughthe sand pack followed by the injection of nanoparticle mixture in theemulsion at the same flow rate through an accumulator. Nanoparticledispersion was injected from the bottom of the flow cell and sampleswere collected from top of the cell in the fraction collector at aregular interval. Prior to the injection, nanoparticle dispersion usedin the experiment was filtered through the 200 nm PTFE filter. The flowtesting diagram is shown in FIG. 4.

Eluting concentration is plotted on tracer 1 and tracer 2 as detected onthe florolog is shown FIG. 9. FIG. 9 shows that for tracer 1, almosthalf of the injected concentration is adsorbed in the sand pack, andover 80% of the tracer 2 seems to be adsorbed in the sand pack. Theinjected tracer concentration remained the same after two hoursindicating that the tracers have very good stability in the emulsion.

Additional results are shown in FIGS. 10 and 11, were FIG. 10 showsintensity of emission as a function of water content for a fluidcontaining an upconverting nanoparticle at 980 nm excitation; and FIG.11 is a schematic illustration of a system that is disposed in adownhole environment according to an embodiment of the disclosure. Theresults indicate that upconverting tracers can be used to determine theamount of water in an emulsion.

Set forth are various embodiments of the disclosure.

Embodiment 1. A method of fracturing multiple productive zones of asubterranean formation penetrated by a wellbore, the method comprising:injecting a fracturing fluid into each of the multiple production zonesat a pressure sufficient to enlarge or create fractures in the multipleproductive zones, wherein the fracturing fluid comprises an upconvertingnanoparticle that has a host material, a dopant, and a surfacemodification such that the upconverting nanoparticle is soluble ordispersible in water, a hydrocarbon oil, or a combination thereof;recovering a fluid from one or more of the multiple production zones;detecting the upconverting nanoparticle in the recovered fluid byexposing the recovered fluid to an excitation radiation having amonochromatic wavelength; and identifying the zone that produces therecovered fluid or monitoring an amount of water or oil in the producedfluid by measuring an optical property of the upconverting nanoparticlein the recovered fluid.

Embodiment 2. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle injected into each of the multipleproduction zones emits a different color of light when exposed to thesame excitation radiation having the monochromatic wavelength.

Embodiment 3. The method of any one of the preceding embodiments,wherein the monochromatic wavelength is about 980 nanometers.

Embodiment 4. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle is immobilized in a matrix orcoated on a solid support, and is configured to be controllably releasedto the produced fluid.

Embodiment 5. The method of any one of the preceding embodiments,further comprising releasing the upconverting nanoparticle from thecomposite to the produced fluid.

Embodiment 6. The method of any one of the preceding embodiments,wherein measuring an optical property of the upconverting nanoparticlein the recovered fluid comprises measuring adsorption spectrum, anemission spectrum, an absorption intensity, a peak absorptionwavelength, a peak emission wavelength, an emission intensity of theupconverting nanoparticle, or a combination comprising at least one ofthe foregoing.

Embodiment 7. The method of any one of the preceding embodiments,wherein the host material of the upconverting nanoparticle is aninorganic compound having an ion of Y³⁺, La³⁺, Gd³⁺, Sc³⁺, Ca²⁺, Sr²⁺,Ba²⁺, Zr⁴⁺ or Ti⁴⁺; and the dopant of the upconverting nanoparticlecomprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺, Pr³⁺, Nd³⁺, Dy³⁺, Ti²⁺, Ni²⁺, Mo³⁺,Re⁴⁺, Os⁴⁺, or a combination comprising at least one of the foregoing.

Embodiment 8. The method of any one of the preceding embodiments,wherein the host material of the upconverting nanoparticle comprisesNaYF₄, NaGdF₄, LiYF₄, YF₃, CaF₂, Gd₂O₃, LaF₃, Y₂O₃, ZrO₂, Y₂O₂S, La₂O₂S,Y₂BaZnO₅, or Gd₂BaZnO₅, and the dopant of the upconverting nanoparticlecomprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺ or a combination comprising at leastone of the foregoing.

Embodiment 9. The method of any one of the preceding embodiments,wherein the dopant comprises about 5 mol % to about 30 mol % of Yb³⁺andabout 1 mol % to about 3 mol % of one or more of the following: Tm³⁺,Ho³⁺, or Er³⁺, each based on the total mole of the upconvertingnanoparticle.

Embodiment 10. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle is surface modified with citricacid.

Embodiment 11. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle has a coating of a polyethyleneglycol, a polyacrylic acid, a derivative thereof, or a combinationcomprising as least one of the foregoing.

Embodiment 12. A method of determining water breakthrough in aproduction well associated with one or more injection wells, the methodcomprising: introducing a fluid comprising an upconverting nanoparticleinto an injection well, the upconverting nanoparticle having a hostmaterial, a dopant, and a surface modification such that theupconverting nanoparticle is soluble or dispersible in both water and ahydrocarbon oil; flowing at least a portion of the fluid comprising theupconverting nanoparticle from the injection well into the productionwell; producing a production fluid from the production well; detectingthe upconverting nanoparticle in the production fluid by exposing theproduction fluid to an excitation radiation having a monochromaticwavelength; and determining water breakthrough in the production well byqualitatively determining the presence or quantitatively measuring theamount of the upconverting nanoparticle in the production fluid.

Embodiment 13. The method of any one of the preceding embodiments,further comprising identifying, upon water breakthrough in theproduction well, the injection well that supplies the breakthrough waterby qualitatively determining the presence of the upconvertingnanoparticle introduced into the injection well.

Embodiment 14. The method of any one of the preceding embodiments,further comprising shutting off the identified injection well.

Embodiment 15. The method of any one of the preceding embodiments,wherein the monochromatic wavelength is about 980 nm.

Embodiment 16. The method of any one of the preceding embodiments,wherein the host material of the upconverting nanoparticle is aninorganic compound having an ion of Y³⁺, La³⁺, Gd³⁺, Sc³⁺, Ca²⁺, Sr²⁺,Ba²⁺, Zr⁴⁺ or Ti⁴⁺; and the dopant of the upconverting nanoparticlecomprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺, Pr³⁺, Nd²⁺, Dy³⁺, Ti²⁺, Ni²⁺, Mo³⁺,Re⁴⁺, Os⁴⁺, or a combination comprising at least one of the foregoing.

Embodiment 17. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle is surface modified with citricacid or the upconverting nanop article has the coating of a polyethyleneglycol, a polyacrylic acid, a derivative thereof, or a combinationcomprising as least one of the foregoing.

Embodiment 18. A method of monitoring well production, the methodcomprising: introducing an upconverting nanoparticle into a wellbore,the upconverting nanoparticle having a host material, a dopant, and asurface modification such that the upconverting nanoparticle is solubleor dispersible in water, a hydrocarbon oil, or a combination thereof;producing a fluid from the wellbore, the produced fluid containing theupconverting nanoparticle; exposing the upconverting nanoparticle to anexcitation radiation from an electromagnetic radiation source within thewellbore; and identifying a zone that produces the fluid or monitoringan amount of water or oil in the produced fluid by measuring an opticalproperty of the upconverting nanoparticle in the produced fluid withinthe wellbore.

Embodiment 19. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle is introduced into the wellbore ina fracturing fluid.

Embodiment 20. The method of any one of the preceding embodiments,wherein the host material of the upconverting nanoparticle comprisesNaYF₄, NaGdF₄, LiYF₄, YF₃, CaF₂, Gd₂O₃, LaF₃, Y₂O₃, ZrO₂, Y₂O₂S, La₂O₂S,Y₂BaZnO₅, or Gd₂BaZnO₅, and the dopant of the upconverting nanoparticlecomprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺ or a combination comprising at leastone of the foregoing.

Embodiment 21. The method of any one of the preceding embodiments,wherein the upconverting nanoparticle is surface modified with citricacid or the upconverting nanop article has the coating of a polyethyleneglycol, a polyacrylic acid, a derivative thereof, or a combinationcomprising as least one of the foregoing.

Embodiment 22. A method of monitoring well production, the methodcomprising: introducing a cable comprising an upconverting nanoparticleinto a wellbore, the upconverting nanop article having a host material,a dopant, and a surface modification such that the upconvertingnanoparticle is soluble or dispersible in water, a hydrocarbon oil, or acombination thereof; exposing the upconverting nanoparticle to anexcitation radiation while the upconverting nanoparticle is exposed to afluid produced from the wellbore; and measuring an optical property ofthe upconverting nanoparticle to determine a zone that produces thefluid or monitoring an amount of water or oil in the produced fluid.

Embodiment 23. The method of any one of the preceding embodiments,wherein introducing a cable comprising an upconverting nanoparticle intoa wellbore comprises introducing a fiber optic cable comprising acoating of the upconverting nanoparticle into the wellbore.

Embodiment 24. The method of any one of the preceding embodiments,wherein introducing a cable comprising an upconverting nanoparticle intoa wellbore comprises introducing a fiber optic cable comprising theupconverting nanoparticle dispersed in at least a portion of the fiberoptic cable.

All ranges disclosed herein are inclusive of the endpoints, and theendpoints are independently combinable with each other. “Or” means“and/or.” All references are incorporated herein by reference.

The use of the terms “a” and “an” and “the” and similar referents in thecontext of describing the invention (especially in the context of thefollowing claims) are to be construed to cover both the singular and theplural, unless otherwise indicated herein or clearly contradicted bycontext. The modifier “about” used in connection with a quantity isinclusive of the stated value and has the meaning dictated by thecontext (e.g., it includes the degree of error associated withmeasurement of the particular quantity, which can be ±10% of thespecified value).

While typical embodiments have been set forth for the purpose ofillustration, the foregoing descriptions should not be deemed to be alimitation on the scope herein. Accordingly, various modifications,adaptations, and alternatives can occur to one skilled in the artwithout departing from the spirit and scope herein.

What is claimed is:
 1. A method of monitoring well production, themethod comprising: introducing an upconverting nanoparticle into awellbore, the upconverting nanoparticle having a host material, adopant, and a surface modification such that the upconvertingnanoparticle is soluble or dispersible in water, a hydrocarbon oil, or acombination thereof; producing an emulsion from the wellbore, contactingthe upconverting nanoparticle with the produced emulsion; exposing theupconverting nanoparticle to an excitation radiation from anelectromagnetic radiation source; and identifying a zone that producesthe emulsion or monitoring an amount of water or oil in the producedemulsion by measuring an optical property of the upconvertingnanoparticle.
 2. The method of claim 1, wherein the optical property ofthe upconverting nanoparticle is measured within the wellbore.
 3. Themethod of claim 1, comprising identifying the amount of water or oil inthe produced emulsion by measuring an optical property of theupconverting nanoparticle in the produced emulsion.
 4. The method ofclaim 1, wherein the upconverting nanoparticle is introduced into thewellbore in a fracturing fluid.
 5. The method of claim 1, wherein theupconverting nanoparticle is introduced into the wellbore via a cablecomprising the upconverting nanoparticle.
 6. The method of claim 5,wherein the upconverting nanoparticles is present as a coating on aportion of the cable.
 7. The method of claim 5, wherein the upconvertingnanoparticles is dispersed in at least a portion of the cable.
 8. Themethod of claim 1, wherein the host material of the upconvertingnanoparticle comprises NaYF₄, NaGdF₄, YF₃, CaF₂, Gd₂O₃, LaF₃, Y₂O₃,ZrO₂, Y₂O₂S, La₂O₂S, Y₂BaZnO₅, or Gd₂BaZnO₅, and the dopant of theupconverting nanoparticle comprises Er³⁺, Yb³⁺, Tm³⁺, Ho³⁺ or acombination comprising at least one of the foregoing.
 9. The method ofclaim 8, wherein the dopant comprises about 5 mol % to about 30 mol % ofYb³⁺ and about 1 mol % to about 3 mol % of one or more of the following:Tm³⁺, Ho³⁺, or Er³⁺, each based on the total mole of the upconvertingnanoparticle.
 10. The method of claim 1, wherein the upconvertingnanoparticle is surface modified with citric acid.
 11. The method ofclaim 1, wherein the upconverting nanoparticle has a coating of apolyethylene glycol, a polyacrylic acid, a derivative thereof, or acombination comprising as least one of the foregoing.
 12. The method ofclaim 1, wherein the upconverting nanoparticle is immobilized in amatrix or coated on a solid support, and is configured to becontrollably released to the produced emulsion.
 13. The method of claim12, further comprising releasing the upconverting nanoparticle from thecomposite to the produced emulsion.
 14. The method of claim 1, whereinmeasuring an optical property of the upconverting nanoparticle in theproduced emulsion comprises measuring adsorption spectrum, an emissionspectrum, an absorption intensity, a peak absorption wavelength, a peakemission wavelength, an emission intensity of the upconvertingnanoparticle, or a combination comprising at least one of the foregoing.15. The method of claim 2, further comprising injecting into each of aplurality of production zones a fluid comprising a qualitativelydistinguishable upconverting nanoparticle, wherein the upconvertingnanoparticle injected into each of the plurality of production zonesemits a different color of light when exposed to an excitation radiationhaving a monochromatic wavelength; and producing the emulsion from oneor more the plurality of the production zones, the produced emulsioncontaining the upconverting nanoparticle.
 16. The method of claim 15,further comprising detecting the zone that produced the emulsion bymeasuring an optical property of the upconverting nanoparticle in theproduced emulsion.
 17. The method of claim 15, wherein the monochromaticwavelength is about 980 nanometers.